Project No. 26892—Filing Package for True-up Proceedings
PUBLIC UTILITY COMMISSION
OF
TEXAS
TRUE-UP PROCEEDING FORM
FOR ELECTRIC UTILITIES
FOR FILINGS PURSUANT TO §39.262
OF THE
PUBLIC UTILITY REGULATORY ACT
GENERAL INSTRUCTIONS
Project No. 26892—Filing Package for True-up Proceedings
General/Schedule Instructions
TRUE-UP PROCEEDING FORM FOR ELECTRIC UTILITIES
PURSUANT TO §39.262
OF THE
PUBLIC UTILITY REGULATORY ACT
General Instructions
1.
This form is prescribed for the use of transmission and distribution utilities, affiliated retail
energy providers, and affiliated power generation companies required to file the true-up
proceeding pursuant to §39.262 of the Public Utility Regulatory Act (PURA). The
objective of this report is to finalize and reconcile stranded costs with the amount of
stranded costs estimated in the proceeding held under PURA §39.201. This report also
provides a means to: recognize any difference in the price of power obtained through the
capacity auctions and the power cost projections assumed in the ECOM model; account for
the results of the annual reports; capture the true-up of price to beat revenues for customers
who are paying the price to beat if market price is lower; review and make appropriate
adjustments for regulatory assets per the provisions of PUC Subst. R. 25.263; and recover
the final fuel balance.
2.
Companies shall file this report with the Commission per the schedule set forth in PUC
Subst. R. 25.263.
3.
Companies shall file the true-up application with the Filing Clerk of the Commission’s
Central Records in accordance with Commission filing standards. The standards
governing both hardcopy and electronic submissions are detailed in PUC Procedural Rules
§ 22.71 and § 22.72. A Microsoft Excel spreadsheet named “True-up Filing Schedules”
has been provided with these instructions. The company shall file an electronic copy of
this completed spreadsheet at the same time it files its printed true-up proceeding
schedules. This spreadsheet shall be filed consistent with the Commission’s electronic
filing standards set out in §22.72(g) of the Procedural Rules. Each sheet of the Excel file is
preformatted to calculate certain items based on company specific inputs. The schedules
in the file entitled “True-up Filing Schedules” attempt to provide a complete listing of the
basic schedules necessary for the true-up filing; however, if any schedules additional to
those in the “True-up Filing Schedule” file are required for the utility’s true-up filing, those
schedules should be included.
4.
Concurrent with the filing of the True-up Proceeding schedules, the reporting transmission
and distribution utility must also separately file with the Commission three (3) complete
sets of workpapers used in the preparation of the testimony and schedules, subject to the
provisions of these instructions dealing with voluminous workpapers. In addition, one (1)
complete set of the same workpapers shall be delivered to the Office of Public Utility
Counsel on the date of filing. To the extent workpapers and any other supporting
schedules are in Microsoft Excel format, all such schedules shall be filed electronically in
Excel format with formulas, cell references, etc. intact.
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General/Schedule Instructions
a.
Workpaper referencing format: The workpaper reference shall always begin with
the characters “WP/” followed by the schedule to which the workpaper refers.
Specific workpapers shall then be referenced by ascending numbers. The resulting
series of workpapers shall have a pyramid structure, with the top workpaper (the
workpaper with the least complicated reference, for example WP/A-1) being the
workpaper which directly reflects the amounts shown on a particular schedule. The
next level down the pyramid would contain information that explains a portion of
the top workpaper. Each successive level down the pyramid would explain
something from the next higher level.
b.
Workpaper content: All assumptions, calculations, sources and data supporting the
amounts included in the schedules shall be included in the workpapers supporting
each schedule.
c.
Workpaper location: All workpapers not considered voluminous shall be organized
and appear in the same order as the schedules they support. All non-voluminous
workpapers shall be provided in both hard copy format as well as electronic format.
d.
Voluminous workpapers: For any supporting workpaper that consists of 500 or
more pages and that cannot be provided in electronic format, the utility may
designate such information as voluminous. All voluminous material shall be made
available in a designated location in Austin on the date of filing. The utility shall
deliver a copy of all voluminous materials to both the Commission staff and the
Office of Public Utility Counsel on the day of filing the True-up Proceeding
Schedules.
5.
The filing should contain company testimony on each schedule relevant and applicable
to the company’s application and also on the issues identified in General Instruction #10.
An executive summary containing an overview of the application should also be included.
6.
Companies using either the Stock Valuation or Partial Stock Valuation methods shall
provide the following additional information in testimony, schedules or workpapers:
a.
Audited historical (2001, 2002 and 2003) financial statements and projected (2004)
financial statements (e.g. income, balance sheet, cash flows) for the affiliated power
generation company.
b.
A summary of each power sales agreement between the affiliated power generation
company and any existing or former affiliated companies, which includes but is not
limited to the type of sale (e.g. bilateral, ancillary services, capacity auction, other),
the amount capacity and energy sold by sale type, capacity, energy and other prices
by sale type, revenues by sale type, expenses by sale type, and a demonstration that
the prices charged for each sale type reflect market conditions.
c.
Support for the affiliated power generation company’s capitalization and dividend
policy including actual and targeted capital structure, dividend to book ratio, and
payout ratio.
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General/Schedule Instructions
d.
Documents provided to investors, investment advisors and/or credit rating agencies
pertaining to future earnings and cash flow prospects of the affiliated power
generation company.
e.
A description of any compensation received for any options, rights of first refusal or
other rights granted to a former affiliate to acquire the stock.
f.
A description and a best estimate of the quantification of the effects of all
commercially reasonable means taken by the affiliated power generation company
that are consistent with protecting and enhancing the value of assets and common
equity.
g.
A list of all affiliate transactions between the transmission and distribution utility,
affiliated retail electricity provider, and the affiliated power generation company
including: a description of the services provided, the method of compensation and
evidence that the prices charged for each sale type reflect market conditions.
h.
A description of any restrictions imposed on the affiliated power generation
company by a current or former affiliate, such as prohibitions on asset sales and
limitations on the amount of debt financing, the use of hedging or similar
procurement processes and how these prohibitions and limitations are consistent
with the exercise of normal business practices.
i.
A description of how the stock of the affiliated power generation company that is
traded in a national exchange was marketed to the public.
Companies using either the “Sale of Asset” or “Asset Exchange” methods shall provide in
testimony, schedules, or workpapers the following additional information as may be
applicable:
a.
A schedule of each and every asset sold or exchanged including, but not limited to,
all assets associated with the production of electricity, including generation plants,
electrical interconnections of the generation plant to the transmission system, fuel
contracts, fuel transportation contracts, water contracts, lands, surface or subsurface
water rights, emissions-related allowances, gas storage facilities, gas pipelines and
gas pipeline interconnections.
b.
All documents provided directly to potential buyers including but not limited to: 1)
Information Memoranda, prototype purchase sale agreements, management
presentation documents, bid instructions for each round of bidding, notices of
selection or elimination, and other correspondence (redacted, if necessary, to prevent
identification of unsuccessful bidders); 2) an index of voluminous data; 3) an index
(including the number of pages) of documents in the data room available to bidders;
4) instructions (in relation to #3) for obtaining access to the electronic data room or
all documents in data room on CD; and 5) all bidders’ Q&A (provided in either
written or electronic form).
.
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General/Schedule Instructions
c.
A general overview of the sale or exchange process, including a discussion of how
the process is consistent with generally accepted practice regarding asset sales.
d.
A copy of the request for proposal (RFP) or other document used to solicit
competitive offers, including but not limited to:
i.
Minimum opening bid or other mandatory terms and conditions
ii.
Information provided to prospective bidders about the assets (e.g. book
value, fuel contracts, projected operating costs, location on the ERCOT grid)
iii.
Bidder qualifications.
iv.
A description of the bidding process.
v.
A list of the major milestones (e.g. time for submitting questions, bidders
conference, time for submitting responses, announce shortlist, negotiations,
final award, and closing date).
vi.
A description of any encumbrances associated with an asset to be sold (e.g.
identify parties having the rights of first refusal, long-term contracts,
environmental and other liabilities, approval process for jointly-owned
facilities).
vii.
Identification of all mitigation measures designed to enhance the value of the
asset.
e.
A complete list of bids and associated terms and conditions that were compared in
each round of bidding to select successful bidders. The only bidder names that must
be matched to a specific final bid and terms are the winning bidders.
f.
A description of the evaluation process, which includes a list all criteria for
determining the best offer, identifies any bids that were rejected and the reasons for
rejection, identifies all persons responsible for evaluation and decision-making,
summarizes the sale terms and conditions, provides justification demonstrating that
the timing of each asset sale would protect and enhance the sale price.
g.
A description and a best estimate of the quantification of the effects of all
commercially reasonable means taken by the affiliated power generation company
to protect and enhance the value of the assets that were sold.
h.
A copy of all submissions to the Commission related to an asset sale or asset
exchange.
Companies proposing a Capacity Auction True-Up will provide the following additional
information:
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a.
An electronic copy of the ECOM Model approved by the Commission in the UCOS
case.
b.
Workpapers supporting the actual busbar sales in 2002 and 2003 by generating unit.
c.
The capacity rating and net energy generation by generating unit in 1999, 2000 and
2001.
d.
Actual fuel costs by generating unit in 1999, 2000, 2001, 2002 and 2003.
e.
Quantification of any nonrecurring fuel costs and any other fuel costs included in
subpart (d) that do not meet the definition of “Eligible Fuel Expense” as defined in
Substantive Rule §25.236(a).
9.
Companies claiming stranded costs shall also provide detailed information on the amount
of generation-related accumulated deferred federal income taxes, excess accumulated
deferred income taxes, and investment tax credits as of 12/31/01 along with supporting
workpapers (see Schedule IX).
10.
The testimony accompanying this filing should support each and every schedule and
workpaper, as applicable, and shall address, at a minimum, the following issues:
a.
Compliance of the particular market valuation methodology used with the specific
requirements set forth in PURA §39.262(h).
b.
Compliance with PURA §39.252(d).
c.
Support for any new regulatory assets to be included in this proceeding that were not
previously determined to be prudent by the Commission in a prior rate case.
11.
Electronic files. To the maximum extent possible, the testimony, schedules, and
workpapers of the filing shall be provided to in an electronic format (e.g., diskette, CD
ROM, or via electronic mail) on the date of filing. Any numerical data provided
electronically shall be in Microsoft Excel on computer diskette or CD ROM.
12.
Confidentiality. If the utility claims that requested information is confidential, a
statement to that effect shall be included in the filing package in the schedule where the
information is requested. The utility shall include a signed statement by its attorney that
presents, for each schedule for which the utility claims that the requested information is
confidential, the claimed reasons that the information should be treated as confidential.
Further, the statement should indicate that the attorney has reviewed the information
sufficiently to state in good faith that the information is confidential.
Until a protective order is issued, the utility shall provide the Commission or a party granted
intervenor status the information claimed to be confidential if the party agrees to be bound
by the draft protective order included at the end of these General Instructions as if it had
been issued. Use of the draft protective order as a confidentiality agreement pending
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issuance of a protective order does not preclude issuance of a protective order that differs
from the draft protective order contained in these instructions.
13.
Companies without stranded costs and which are only required to file for the true-up of
price-to-beat revenues and/or the final fuel reconciliation should complete only those
relevant schedules of this filing package.
14.
In addition to each portion of the filing that is attested to and sponsored by individual
witnesses, each True-up Proceeding Filing shall contain a general attestation, by an officer
or manager, under whose direction relevant portions of the filing are prepared, of each of
the transmission and distribution utility, affiliated retail energy provider, and affiliated
power generation company that is required to file this report.
15.
If it is necessary to revise any schedule after the initial filing of the True-up, a new
electronic version and four (4) printed copies of the report and any explanatory testimony
shall be provided. The electronic version and all printed copies shall be labeled “revised”
and include the date of revision. Additionally, a summary table should be included listing
each revised schedule and an explanation of the change. Copies of all revisions and
explanatory testimony should be provided electronically to the Commission Staff, the
Office of Public Utility Counsel, and all intervenors.
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General/Schedule Instructions
CONFIDENTIALITY
This section shall include a signed statement by the utility’s attorney that presents, for each
schedule for which the utility claims that the requested information is confidential, the claimed
reasons that the information should be treated as confidential and that states that the attorney has
reviewed the information sufficiently to state in good faith that the information is confidential.
This section shall also contain a draft protective order for parties’ use prior to the issuance of a
protective order.
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Schedule Instructions
Schedule I: Determination of True-up Amount
No inputs are required on this schedule.
This schedule will automatically determine the utility’s true-up amount and true-up amount
remaining to be collected/refunded, based on items calculated on other schedules.
Schedule I-A: Determination of Mitigation to be Refunded
No inputs are required on this schedule.
Line 1 shall reflect any market value in excess of book value. Amount is automatically
displayed as a positive amount from calculations from other schedules.
Line 2 automatically reflects the mitigation amount due to redirected depreciation as
determined on Schedule III-E.
Line 3 automatically reflects the excess earnings depreciation mitigation amount net of any
amounts refunded in 2002 through 2004 as determined on Schedule III-F.
Line 4 automatically reflects the net mitigation of redirected depreciation and excess
earnings after taking into account any refund of excess earnings mitigation in 2002 through
2004.
Line 5 automatically reflects mitigation to be refunded, which is the lessor of the net
mitigation from Line 4 or the market value in excess of book value from Line 1. This results
in the total refund being capped at the total amount of mitigation.
Schedule II: Comparison of Book Value to Market Value
No inputs are required on this schedule.
This schedule will automatically compare the utility’s book value to market value, based on
items calculated on other schedules. If Line 4 is positive, stranded costs that exist will be
shown on Line 5. If Line 4 is negative, the market value in excess of book value will be
shown on Line 6.
Schedule III: Summary of Net Book Value of Generation Assets to Include in True-up
Determination
No inputs are required on this schedule.
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This schedule will automatically determine the utility’s net book value of generation assets
to include in the true-up, based on items calculated on other schedules. The workpapers
should include a schedule that matches the total net book value of generation assets with the
total market value of those generation assets.
Schedule III-A: Net Book Value (Before Mitigation) of Generation Assets on Books as of
12/31/01
Line 1 column (a) reflects generation related electric plant in service by FERC Chart of
Accounts (FCA) that is on the regulated books at 12/31/01. This amount must equal the
amount reflected on the regulated balance sheet for the integrated utility or power
generation company at 12/31/01. Plant in service will not include investment that is
otherwise included in the affiliated TDU’s Transmission Cost of Service (TCOS) and in the
cost of service used to set the Tariff for Retail Delivery Service. Supporting workpapers
will be provided to show that investments booked to FERC Accounts other than 310
through 346 are generation-related and to explain any differences between this filing and
the generation-related amounts determined in the affiliated TDU’s Unbundled Cost of
Service (UCOS) filing pursuant to PURA §39.201.
Line 1 column (b) reflects generation related accumulated depreciation by FERC Chart of
Account that is on the regulated books at 12/31/01. This amount should exclude any
accumulated depreciation due to redirected depreciation or excess earnings depreciation.
Accumulated depreciation will not include accumulated depreciation that is otherwise
included in the affiliated TDU’s TCOS filing and in the cost of service used to set the Tariff
for Retail Delivery Service. Supporting workpapers will be provided to show that
accumulated depreciation booked to FERC Accounts other than 310 through 346 is
generation-related and to explain any differences between this filing and the generationrelated amounts determined in the affiliated TDU’s UCOS filing pursuant to PURA
§39.201.
Line 2 reflects the net of Line 1(a) and Line 1(b), which results in Net Electric Plant in
Service before the effects of mitigation.
Line 3 reflects any generation related Construction Work in Progress on the regulated books
at 12/31/01.
Line 4 reflects any generation related Plant Held for Future Use on the regulated books at
12/31/01.
Line 5 reflects any nuclear fuel and nuclear fuel stock inventory on the books at 12/31/01.
Line 6 reflects any other generation-related assets at 12/31/01 not included above.
Workpapers should fully describe and explain each type of other asset included.
Line 7 reflects net book value of generation assets before mitigation as of 12/31/01.
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Integrated Utility or Generation Company balance sheets on a regulated basis as of
12/31/01 should be included as part of the workpapers. Workpapers should be provided for
each fixed capital account in this summary (aggregate) schedule.
Schedule III-B: Environmental Expenditures Not Included in Book Value as of 12/31/01 but
Incurred Through 5/01/03
Line 1 reflects all environmental expenditures that qualify under Section 39.263.
Line 2 reflects the amount of the qualified environmental expenditures that are included in
the net book value of generation assets as of 12/31/01 (before mitigation).
Line 3 calculates the amount of environmental expenditures not included in book value as
of 12/31/01 but incurred before 5/01/03.
A detailed schedule documenting the amounts and types of expenditures should be included
as part of the workpapers
Schedule III-C: Deferred Debits as a Result of Discontinuing Application of SFAS No. 71
This schedule should include deferred debits that were recorded as a result of discontinuing
application of SFAS No. 71. The deferred debits should be listed by category. Journal
entries and supporting calculations should be included as part of the workpapers.
Schedule III-D: Summary of Above-Market Purchased Power Costs
No inputs are required on this schedule.
Based on items calculated on other schedules, this schedule will automatically determine
the above-market purchased power costs.
Schedule III-D-1: Summary of Amount Utility Would Pay Third Party to Take Contract
No inputs are required on this schedule.
Based on items calculated on other schedules, this schedule automatically calculates the
above market purchased power cost for each contract if the offer is structured as the
amount the utility would pay third parties to take the purchased power contracts.
Schedule III-D-1-a, III-D-1-b, III-D-1-c: Amount Utility Would Pay Third-Party to Take
Contract—Detail
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This schedule should be prepared for each contract. Three schedules have been provided,
but additional schedules should be created if necessary.
Line 1 should reflect the electric utility's Power Contract MW obligation.
Line 2 should reflect the MW obligation and above-market costs (i.e., lowest costs to the
electric utility paying to relieve itself of the obligation) associated with each of the highest
three offers for power under each existing purchased power contract.
Line 3 automatically adds up the MW obligations and above market costs associated with
each offer.
Line 4 automatically calculates the weighted average cost of the highest three offers based
on each offer's market cost and corresponding MW obligations. No input is required for
this line.
Line 5 calculates the total above market cost for the contract based on the Line 4 weighted
average costs and the unsold portion, if any, of the utility's power contracts obligation from
Line 1.
Details of the purchased power contacts should be included as part of the workpapers.
All offers should be included as part of the workpapers.
Schedule III-D-2: Summary of Amount Third-Party Would Pay Utility for Power under
Contract
No inputs are required on this schedule.
Based on items calculated on other schedules, this schedule automatically calculates the
above market purchased power cost for each contract if the offer is structured as the
amount the third party pays to take power under the purchased power contracts.
Schedule III-D-2-a, III-D-2-b, III-D-2-c: Amount Third-Party Would Pay Utility for Power
under Contract—Detail
This schedule should be prepared for each contract. Three schedules have been provided,
but additional schedules should be created if necessary.
Line 1 should reflect the electric utility's Power Contract MW obligation.
Line 2 should include the amount for wholesale demand and energy costs that a utility is
obligated to pay under the existing purchased power contract. This amount should be the
net present value of the obligation. The discount rate used in the net present value
calculation should be the utility’s cost of capital approved in its unbundled cost-of-service
proceeding. Details of the purchased power contacts should be included as part of the
workpapers.
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Line 3 reflects the MW purchase commitment and market value for each of the highest
three offers for Line 1 demand and energy. All offers should be included as part of the
workpapers.
Line 4 automatically displays sums of the MW purchase obligation and market value for
each offer.
Line 5 is the weighted average of the three highest offers of Line 3 weighted by market
value and MW purchase commitment. No input is required for this line.
Line 6 is the total market value of the contract based on the weighted value on Line 5 and
any unsold MW from the utility's MW purchase obligation in Line 1. No input is required
for this line.
Line 7 reflects the above market purchased power costs to include in the net book value of
generation assets. No input is required for this line.
Schedule III-E: Redirected Depreciation—Net of Reversed Amounts
Line 1 reflects by year the utility’s redirected depreciation for 1998 through 2001 pursuant
to PURA Section 39.256.
Line 2 reflects by year the amount of redirected depreciation for 1998 through 2001 that has
been reversed pursuant to commission order.
Line 3 automatically reflects the total redirected depreciation that has not been reversed.
No input is required.
Supporting workpapers should be included. The information provided should include the
docket numbers and relevant final-order excerpts from the proceedings that authorized the
reversal of the redirected depreciation, and the dates on which the depreciation was
reversed.
Schedule III-F: Excess Earnings Depreciation Mitigation—Net of Refunded Amounts
This schedule determines the amount of excess earnings depreciation that can be applied to
reduce the net book value of generation assets.
Line 1 reflects by year the utility’s excess earnings depreciation calculated pursuant to the
annual report required under Section 39.257(b) for 1999 through 2001 and any excess
earnings depreciation permitted pursuant to a transition plan in 1998. The amount shown
should include adjustments made after December 31, 2001 (including adjustments due to
annual report review). The amount shown should be the total excess earnings determined
by the commission even if the commission has subsequently ordered the refund of excess
earnings depreciation and precluded future excess earnings depreciation.
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Line 2 automatically reflects the total excess earnings depreciation possible pursuant to the
annual report. No input is required.
Line 3 through Line 5 reflects by year the amount of excess earnings depreciation in Line 2
that has been refunded (including return) to customers. 2002 and 2003 should reflect actual
refunded amounts. 2004 should reflect an estimate of the refunded amounts through the
projected date of the true-up final order.
Line 6 automatically reflects the total excess earnings depreciation that has been refunded.
No input is required.
Line 7 is the difference between the amount of excess earnings depreciation possible and
the amount of excess earnings depreciation refunded to customers. This difference is the
amount of mitigation that has not been refunded and can be used to reduce net book value
for the true-up.
The company’s final Annual Reports for 1998 through 2001 should be included as part of
the workpapers.
Schedule III-G: Net Book Value of Nuclear Assets (if ECOM Model used)
This schedule should include the net book value of nuclear assets at 12/31/01 if nuclear
assets are to be valued through the ECOM model.
Line 1 automatically reflects the net book value of generation assets before mitigation. No
input is required.
Line 2 should reflect redirected depreciation applied to nuclear assets.
Line 3 should reflect excess earnings depreciation mitigation that has not been refunded to
customers if applied to nuclear assets.
Line 4 automatically reflects the total net book value of nuclear assets to be included in the
ECOM model. No input is required.
Schedule III-G-1: Net Book Value of Nuclear Assets before Mitigation (if ECOM Model used
for valuation of nuclear assets)
Line 1 column (a) reflects nuclear related electric plant in service by FERC Chart of
Account that is on the regulated books at 12/31/01. This amount must equal the amount
reflected on the regulated balance sheet for the integrated utility or power generation
company at 12/31/01.
Line 1 column (b) reflects nuclear related accumulated depreciation by FERC Chart of
Account that is on the regulated books at 12/31/01. This amount must equal the amount
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reflected on the regulated balance sheet for the integrated utility or power generation
company at 12/31/01.
Line 2 reflects the net of Line 1(a) and Line 1(b), which result in Net Electric Plant in
Service
Line 3 reflects any nuclear related Construction Work in Progress on the books at 12/31/01.
Line 4 reflects any nuclear related Plant Held for Future Use on the books at 12/31/01.
Line 5 reflects any nuclear fuel on the books at 12/31/01.
Line 6 reflects any other generation-related assets sold that are not included above.
Line 7 reflects net book value of generation assets before mitigation as of 12/31/01.
Integrated Utility or Generation Company balance sheets on a regulated basis as of
12/31/01 should be included as part of the workpapers.
Schedule IV: Summary of Market Value of Generation Assets
No inputs are required on this schedule.
This schedule will automatically determine the market value of generation assets from all
market value methods, based on items calculated on other schedules.
Schedule IV-A: Summary of Sale of Assets Method
No inputs are required on this schedule.
This schedule will automatically calculate the net value realized from all sales of assets.
Schedule IV-A-1, IV-A-2, IV-A-3: Sale of Assets Method--Detail
This schedule should be prepared for each sale transaction. Three schedules have been
provided, but additional schedules should be created if necessary.
Line 1 should include any cash proceeds.
Line 2 should include any debt assumed by the buyer as part of the transaction.
Line 3 should list each type of other in-kind or non-cash compensation received as part of
the transaction, including a copy of any agreements, indemnities, term sheets, or other
explanation of the nature of each type of compensation.
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Line 4 automatically calculates total sales proceeds from the transaction. No input is
required.
Line 5 should list each transaction cost.
Line 6 automatically calculates the net value realized from the sale transaction. No input is
required.
Detail and support for each sale should be included as part of the workpapers including a
description of each asset sold, the sales price, and transaction costs related to the sale.
Schedule IV-B: Stock Valuation Method
This schedule should be prepared for each publicly traded corporation (transferee
corporation) created pursuant to Section 39.262(h)(2).
Line 1 should include the total number of shares sold or spun off.
Line 2 should include the percent of shares sold or spun off.
The chart below Line 3 contains inputs for the closing stock price for the 120 consecutive
trading days prior to the filing date.
Line 4 automatically calculates the highest resulting average daily closing price of the
common stock over 30 consecutive trading days out of the last 120 consecutive trading
days. The highest average is derived from all the possible consecutive 30-day averages
automatically calculated on page 2 of this schedule (the bottom portion of the Excel sheet).
Line 5 reflects the total number of common stock shares for the publicly traded corporation.
Line 6 reflects the market value of the equity, which is the result of Line 4 average closing
price multiplied by Line 5 total shares. No input is required.
Line 7 should reflect the amount of debt securities of the publicly traded corporation. The
debt securities should be determined as the average debt balance over the same 30-day
period used to determine the average stock price (i.e., for the same time period underlying
the value on Line 4). Balance sheets that reflect as closely as possible the same 30-day time
period should be included in the workpapers.
Line 8 should include the amount of preferred stock securities of the publicly traded
corporation. The preferred stock securities should be determined as the average preferred
stock balance over the same 30 days used to determine the common stock price (i.e., for the
same time period underlying the value on Line 4). Balance sheets that reflect as closely as
possible the same 30-day time period should be included in the workpapers.
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Line 9 should include the net book value of assets acquired by the transferee corporation
from an entity other than the affiliated electric utility or power generation company that
should be subtracted from market value.
Line 10 is the market value determined through the stock valuation method.
Schedule IV-C: Partial Stock Valuation Method
This schedule should be prepared for each publicly traded corporation (transferee
corporation) created pursuant to Section 39.262(h)(3).
Line 1 should include the total number of shares sold or spun off.
Line 2 should include the percent of shares sold or spun off.
The chart below Line 3 contains inputs for the closing stock price for the 120 consecutive
trading days prior to the filing date.
Line 4 automatically calculates the highest resulting average daily closing price of the
common stock over 30 consecutive trading days out of the last 120 consecutive trading
days. The highest average is derived from all the possible consecutive 30-day averages
automatically calculated on page 2 of this schedule (the bottom portion of the Excel sheet).
Line 5 reflects the total number of common stock shares for the publicly traded corporation.
Line 6 reflects the market value of equity, which is the result of Line 4 average closing
price multiplied by Line 5 total shares. No input is required.
Line 7 should reflect the amount of debt securities of the publicly traded corporation. The
debt securities should be determined as the average debt balance over the same 30-day
period used to determine the average stock price (i.e., for the same time period underlying
the value on Line 4). Balance-sheet information from the most recent quarter preceding the
period reflecting the highest 30-day stock price average should be provided in workpapers.
Additionally, monthly updates of the balance sheet and debt balances until the most recent
month that overlaps—i.e., extends beyond—the period reflecting the highest 30-day stock
price average should be included in the workpapers.
Line 8 should include the amount of preferred stock securities of the publicly traded
corporation. The preferred stock securities should be determined as the average preferred
stock balance over the same 30 days used to determine the common stock price (i.e., for the
same time period underlying the value on Line 4). Balance-sheet information from the
most recent quarter preceding the period reflecting the highest 30-day stock price average
should be provided in workpapers. Additionally, monthly updates of the balance sheet and
preferred stock balances until the most recent month that overlaps—i.e., extends beyond—
the period reflecting the highest 30-day stock price average should be included in the
workpapers.
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Line 9 should include the net book value of assets acquired by the transferee corporation
from an entity other than the affiliated electric utility or power generation company that
should be subtracted from market value.
Line 10 is the market value determined through the partial stock valuation method for each
publicly traded corporation.
Schedule IV-D: Exchange of Assets Method
List the market value of assets received through the Exchange Method.
supporting workpapers.
Include all
Schedule IV-E: ECOM Model Method—Stranded Cost Valuation of Nuclear Assets
This schedule should include the stranded-cost amount of nuclear assets calculated pursuant
to the ECOM model if a market valuation method has not been used to value nuclear assets.
ECOM model reports should be included as part of the workpapers.
Schedule V: Final Fuel Balance (Including Interest)
This schedule should include the final fuel balance from the fuel reconciliation approved in
2003 and interest on that balance through the projected date of the true-up final order, as
calculated pursuant to the provisions of PUC Substantive Rule 25.263(h)(4).
Include all supporting workpapers.
Schedule VI: True-up of Capacity Auction Proceeds
Lines 1 through 4 should contain market-revenue data from the ECOM model underlying
the company’s UCOS ECOM estimate. Data for 2002 and 2003, lines 12, 13, and 14 from
the “Plant Economics” worksheet of the ECOM model should be used as inputs.
Lines 5 through 8 should contain fuel data from the ECOM model’s “Cost Partition”
worksheet. Data from 2002 and 2003, lines 33, 34, and 35 should be used as inputs.
Line 9 should contain total busbar sales, by meter, per books for 2002 and 2003. Include a
breakdown of the monthly busbar sales by unit and by capacity auction product and all
other supporting workpapers. If this type of information is not available, please explain and
demonstrate how the company can comprehensively assess its operations without the use of
such detailed sales information, and why it is not necessary and prudent to compile and
maintain a detailed record of relevant data.
Line 10 automatically calculates the average capacity auction price for 2002 and 2003 based
on inputs to the bottom portion of the schedule. No input is required directly into line 10.
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Line 11 automatically calculates the total capacity auction revenues for 2002 and 2003
based on the amounts from lines 9 and 10. No input is required directly into line 11.
Line 12 should contain the company’s actual fuel costs per books for 2002 and 2003.
Include a breakdown of monthly actual fuel costs, capacity rating and heat rate by unit and
by capacity auction product, and all other supporting workpapers. As part of these
workpapers, companies should include, for the period from 1/1/02 to 12/31/03, the daily gas
prices as defined in PUC Subst. R. §25.381(c)(9) and, additionally, the Houston Ship
Channel gas prices contained in the publication Inside FERC (as referred to in Schedule CA
at Section K(2)(c)(ii)(B)(1)(a)(ii) of the stipulation in Docket No. 23744).
Line 13 automatically calculates the total amount of capacity auction true-up based on the
amounts in lines 4, 8, 11, and 12. No input is required directly into this line.
The bottom portion of the schedule, under the heading “Capacity Auction Sales,” should
contain data from the company’s capacity auctions held during the years 2002 and 2003.
No input is required. Based on information in Schedule VI-A, the average capacity auction
price is automatically calculated at the bottom of the schedule and carried over to line 10.
Schedule VI-A: Detailed Summary of All Capacity Auctions by Product
No inputs are needed for the capacity auction revenues shown in the first set of columns,
which have amounts carried over from Schedule VI-B. In the second set of columns,
include the MWh sales by month by capacity auction product. Separate rows are provided
for the auctions conducted each trimester and for the one-year and two-year strips. The sum
of Total Revenues and MWh sales of capacity auction products is carried over to Schedule
VI.
Schedule VI-B: Detail of Capacity Auction Revenues
Include revenues derived from capacity payments, energy payments, and other revenues by
month by capacity auction product. Separate rows are provided for the auctions conducted
each trimester and for the one-year and two-year strips. The sum of the revenues by
product for each auction is carried over to Schedule VI-A.
Schedule VI-C: General Summary of Capacity Auction Results
For each auction and for each auction product, input the number of entitlements offered, the
number of entitlements sold, the fuel price (in $/MWh) for base load products, the
minimum opening price (in $/kW), and the final sale price in ($/kW). A separate set of
columns is provided for the auctions conducted each trimester and for the one-year and twoyear strips. The workpapers accompanying this Schedule should show that the number of
entitlements offered is consistent with PUC SR §25.381. This information should be
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consistent with the information provided prior to each auction and reported to the
Commission.
Schedule VII: Summary of True-Up of Price-To-Beat Revenues (Retail Clawback)
No inputs are required on this schedule.
This schedule will automatically determine the total amount of the true-up of price-to-beat
revenues, based on items calculated on other schedules.
Schedule VII-A: True-Up Of Price-To-Beat Revenues (Retail Clawback)—RESIDENTIAL
Customers
Note: To the extent that final information for end-of-year 2003 and beginning-of-year 2004
is not yet available at the time the company files its report, the company should include in
the filing its best estimate of the data and then provide finalized updates during the
pendency of the proceeding.
Line 1 should reflect the residential Net Price to Beat in the ATDU Region in cents/kWh as
of the last day of each of the eight quarters in the years 2002 and 2003. This price is the
average residential PTB rate for 1,000 kWh per month (expressed in cents per kWh) less the
average nonbypassable delivery charge for 1,000 kWh per month (expressed in cents per
kWh) established under PURA Section 39.201 applicable to residential customers.
Line 2 shall reflect the residential Net Market Price in the ATDU Region in cents/kWh as
of the last day of each of the eight quarters in the years 2002 and 2003. This price is the
volume-weighted average price, less average nonbypassable charges (each expressed in
cents per kilowatt-hour), calculated by the independent third party for residential electric
service provided by non-affiliated retail electric providers and non-provider of last resort
(POLR) service providers competing in the TDU region.
Line 3 automatically calculates the differential between Residential Net Price to Beat and
Net Market Price.
Line 4 shall reflect the total kWh billed to residential PTB customers of the AREP for each
of the eight quarters in the years 2002 and 2003.
Line 5 automatically calculates any excess revenues resulting from the excess of the PTB
over the market price for each quarter multiplied by the total kWh consumed for that
quarter. No input is required directly into this line.
Line 6 automatically calculates the total revenue differential for all eight quarters. No input
is required directly into this line.
Line 7 should reflect the number of residential customers served by the AREP inside the
ATDU region on 1/1/04.
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Line 8 should reflect the number of residential customers served by the AREP outside the
ATDU region on 1/1/04.
Line 9 automatically subtracts line 8 from line 7 and shows the net residential customers
served by the AREP on 1/1/04. No input is required directly into this line.
Line 10 reflects the maximum per-customer charge of $150 that an AREP may credit an
ATDU.
Line 11 automatically calculates the maximum amount that the AREP will credit the ATDU
based on the net number of customers calculated in line 9 multiplied by the $150 maximum
per-customer charge in line 10. No input is required directly into this line.
Line 12 automatically calculates the lesser of line 6 or line 11 as the actual amount that the
AREP will credit the ATDU. No input is required directly into this line.
Schedule VII-B: True-Up Of Price-To-Beat Revenues (Retail Clawback)—SMALL
COMMERCIAL Customers
Note: To the extent that final information for end-of-year 2003 and beginning-of-year 2004
is not yet available at the time the company files its report, the company should include in
the filing its best estimate of the data and then provide finalized updates during the
pendency of the proceeding.
Additionally, note that for purposes of this schedule, the term “small commercial
customer” does not include unmetered lighting accounts unless such an account has
historically been treated as a separate customer for billing purposes
Line 1 should reflect the small commercial Net Price to Beat in the ATDU Region in
cents/kWh as of the last day of each of the eight quarters in the years 2002 and 2003. This
price is the average small commercial PTB rate for 35 KW or 75,000 kWh per month
(expressed in cents per kWh) less the average nonbypassable charges for 35 KW or 75,000
kWH per month (expressed in cents per kWh) established under PURA Section 39.201
applicable to small commercial customers.
Line 2 shall reflect the small commercial Net Market Price in the ATDU Region in
cents/kWh as of the last day of each of the eight quarters in the years 2002 and 2003. This
price is the volume-weighted average price, less average nonbypassable charges (each
expressed in cents per kilowatt-hour), calculated by the independent third party for small
commercial electric service provided by non-affiliated retail electric providers and nonprovider of last resort (POLR) service providers competing in the TDU region.
Line 3 automatically calculates the differential between the small commercial Net Price to
Beat and Net Market Price.
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Line 4 shall reflect the total kWh billed to small commercial PTB customers of the AREP
for each of the eight quarters in the years 2002 and 2003.
Line 5 automatically calculates any excess revenues resulting from the excess of the PTB
over the market price for each quarter multiplied by the total kWh consumed for that
quarter. No input is required directly into this line.
Line 6 automatically calculates the total revenue differential for all eight quarters. No input
is required directly into this line.
Line 7 should reflect the number of small commercial customers served by the AREP inside
the ATDU region on 1/1/04.
Line 8 should reflect the number of small commercial customers served by the AREP
outside the ATDU region on 1/1/04.
Line 9 automatically subtracts line 8 from line 7 and shows the net small commercial
customers served by the AREP on 1/1/04. No input is required directly into this line.
Line 10 reflects the maximum per-customer charge of $150 that an AREP may credit an
ATDU.
Line 11 automatically calculates the maximum amount that the AREP will credit the ATDU
based on the net number of customers calculated in line 9 multiplied by the $150 maximum
per-customer charge in line 10. No input is required directly into this line.
Line 12 automatically calculates the lesser of line 6 or line 11 as the actual amount that the
AREP will credit the ATDU. No input is required directly into this line.
Schedule VIII: Summary of Regulatory Assets
No inputs are required on this schedule.
This schedule will automatically determine the utility’s regulatory assets to be included in
the true-up amount, based on items calculated on other schedules.
Schedule VIII-A: Regulatory Assets That Exceed The Amount Approved in a Rate Order
If as part of a Financing Order, all issues regarding recovery of regulatory assets have been
fully resolved, this schedule does not apply. Include a copy of Financing Order in
workpapers.
This schedule should list out each regulatory asset amount that was included in a transition
charge not previously included in a rate order effective on or before September 1, 1999.
The Line 6 disallowance amount should be assumed to be zero until after commission
review. Detail of the costs should be included as part of workpapers.
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Schedule VIII-B: Regulatory Assets On Books as of 12/31/98 Not Covered Under a Financing
Order
This schedule should list out each regulatory asset amount on the books as of 12/31/98 not
previously covered by a Financing Order. Detail and support of each regulatory asset
amount should be included as part of workpapers.
Schedule IX: Tax Information Related to Generation Assets as of 12/31/01
Provide detailed information on the amount of generation-related accumulated deferred
federal income taxes, excess accumulated deferred income taxes, and investment tax credits
as of 12/31/01. Provide supporting workpapers in your filing.
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